In general operation, well liquids are carried out of well tubing by high velocity gas. However, as a well declines, liquids can start to fall back to the bottom of the well. This can result in production decreases because well liquids are not carried to the surface. In addition, the liquid fall back can exert back pressure on the formation, which can “load up” the well. Inflow from the formation is impeded as average flowing bottom hole pressure increases. A plunger lift system can provide a method for unloading fluids in hydrocarbon wells, whereby production can be increased and/or optimized with minimal interruption to production.
In a typical plunger lift system, a plunger can freely travel to the bottom of the well where it may be used to help push liquids to the surface where it is collected. Using the well's own energy for lift, the plunger rises to the surface from the bottom of the well, bringing up liquids. The mechanical interface created by the plunger between any accumulated liquids and gas helps to prevent liquid fallback. Not only does this help in boosting a well's lifting efficiency, the afore-mentioned back pressure can be relieved, which helps to increase inflow from the formation. A plunger can also help keep the well tubing free of paraffin, salt and/or scale build-up.
After the liquids that are carried by the plunger are discharged, and the gas pressure is reduced, the plunger descends by gravity to the bottom of the well for another cycle. When the plunger hits the bottom or contacts fluid in the well, gas pressure that has been allowed to build under the plunger will cause the plunger to rise again with any accumulated fluid.
As described above, a plunger travels to the bottom of the well so it can artificially lift liquids to the surface. The plunger's travel time can be dependent on factors such as geology, gas type, plunger type, etc. The disclosed device can help to minimize plunger travel time and maximize the ability of a plunger lift system to unload a well by incorporating one or more plungers in a system. In addition, the disclosed device can utilize pressure stored in the tubing of a lower stage to lift the fluid and plunger in a higher stage. The disclosed device can be used to partition a well's tubing into discrete and independent sections wherein discrete and independent plungers can operate.
U.S. Pat. No. 7,080,691 to Kegin discloses one such plunger lift tool. Kegin teaches a device that can be removably positioned in oil and gas wells to create multiple stages for use with multiple plungers. Kegin's tool comprises 1) a shaft assembly defining a passageway therein having a top, a spreader cone, and a bottom; 2) a sleeve defining a passageway therein having a top with an expandable bushing and a bottom; 3) a positioning means defining a passageway therein for removably installing said plunger lift tool in said well tubing, said positioning means attached to said bottom of said sleeve; 4) at least one shear pin for selectively holding said shaft assembly in position with said sleeve wherein said at least one shear pin breaks when a downward force F is applied to said top of said shaft assembly allowing said shaft assembly spreader cone to cooperate with said expandable bushing of said sleeve thereby creating a seal between said plunger lift tool and said well tubing; and a retrieval assembly attached to said top of said shaft assembly for removing said tool from said well wherein said retrieval assembly includes a bypass cage with a ball check valve therein. U.S. Pat. No. 7,080,692 to Kegin discloses a method of using such a plunger lift tool.
As disclosed in the above-mentioned references, Kegin's shear pin breaks so the sleeve can slide and the cone can spread to create the seal. After the tool is retrieved from its downhole location, the brass pins must be reset or replaced. Kegin's tool provides for a one-time use. In addition, the pins sheared from the device will fall into the tubing, potentially causing problems for a traveling plunger and other downhole equipment. Other problems encountered by the Kegin device can include damage to the tool itself when the bushing jams in the tubing and tears as it rubs against the tubing and joint collars when the cone fails to disengage the bushing or when the bushing fails to return to its original shape and diameter when the tool is to be removed from the well tubing. Parts of the tool, such as the bushing, must then be fished out of the tubing to prevent problems for a traveling plunger and other downhole equipment. If a device such as Kegin's is improperly set or positioned in a well tubing, the unit must be removed from the tubing and redressed before it can be repositioned (properly or improperly) in the tubing once again. In short, it must be completely removed from the well and redressed before it can be used again.